Over the last decade, substantial resources have been directed towards developing cost-efficient processes of capturing carbon dioxide (CO2) from large point sources, such as fossil fuel power plants, cement factories, oil refineries, or iron and steel mills, and injecting and isolating the captured CO2 in deep geological formations.
Carbon Capture and Storage (CGS) consists of three major steps: CO2 capture from the energy conversion process; CO2 transport; and CO2 storage. For each step there are currently several technology options, with different levels of performance and maturity, so numerous constellations for CCS can be envisaged although many technological hurdles remain to be overcome before commercialization is feasible.
Carbon Capture
The problems of carbon capture from fossil fuel power plants are: the low pressure and dilute concentration dictate a high actual volume of gas to be treated; trace impurities in the flue gas tend to reduce the effectiveness of the CO2 adsorbing processes; compressing captured CO2 from atmospheric pressure to typical pipeline pressure (102 to 136 atm or 1,500 to 2,000 psi) in which CO2 can be transported more economically and efficiently, represents a large parasitic load.
In broad terms, there are three CO2 capture methods that are generally indistinguishable in cost and efficiency: post-combustion capture that separate CO2 from flue gases produced by combustion of a primary fuel (coal, natural gas, oil or biomass) in air, pre-combustion capture that process the primary fuel in reactor to produce separate streams of CO2 for storage and H2 which is used as a fuel, and oxyfuel combustion that uses oxygen instead of air for combustion, producing a flue gas that is mainly H2O and CO2 and which is readily captured. These three prior-art methods are illustrated schematically in FIG. 1.
The capture of CO2 is not necessarily limited to the above mentioned techniques and it may be possible to pick and choose among the elements of the main CO2 capture systems and develop hybrid systems which are possibly cheaper and more energy efficient. To date, the proposed hybrid carbon capture systems comprise: post combustion capture with oxygen enriched combustion; regenerable sorbents (calcium looping) with oxyfuel combustion; post combustion capture in IGCC plants; gasification with oxyfuel; and gasification with chemical looping.
However, the proposed hybrid carbon capture systems have not been physically studied or tested with one exception: the use of oxyfuel combustion for the calcination step in carbonate looping capture. The existence of hybrid capture concepts means that capture systems may not have to be limited to the three “conventional” techniques outlined above.
Four different CO2 separation techniques are used in CO2 capture processes. These are 1) absorption, 2) adsorption, 3) membrane separation, and cryogenic processes. Absorption processes for CO2 separation can be divided into two categories: (a) chemical absorption where the solvent (usually alkanolamines) chemically reacts with CO2 and (b) physical absorption where the solvent only interacts physically with CO2 (such as glycol ethers in the Selexol Process).
One of the methods proposed for CO2 concentrating is by absorption and stripping with aqueous amine. The basic process of CO2 scrubbing by amine was patented in 1930 (U.S. Pat. No. 1,783,901). Amine scrubbing is a well-understood and widely used technology. Aqueous amine sorbents have been successfully used to clean carbon dioxide and hydrogen sulphide from natural gas and industrial waste streams. Extending it to a flue gas process, a solvent absorbs CO2 from flue gas and is regenerated by heating for several hours in recovery columns at 150° C. This technology can be applied to already existing plants; components in the non-integrated equipment can be replaced, developed, and upgraded without fundamental impact on the power plant.
However, there are some major disadvantages. The equipment will be very large, comparable with the footprint size of a coal-fired power plant and this is a significant challenge when dealing with existing plants that have fixed layouts and limited open space. Furthermore, large volumes of solvent and water are needed; heating to regenerate the solvent reduces efficiency and can produce toxic byproducts, emissions of solvents from recovery columns have to be scrubbed and eliminated, and the solvent that is degraded by flue-gas impurities needs to be disposed. Furthermore, the cost of amine scrubbing to capture carbon dioxide, then compressing it to pipeline pressure, is prohibitively expensive.
Another method proposed for CO2 concentrating is by oxy-fuel combustion in which the fuel is burned with a mixture of recirculated flue gas and oxygen instead of air. The absence of nitrogen (by excluding air) produces a flue gas stream with a high concentration of CO2, and therefore facilitates capture. Oxy-fuel combustion is being developed for both turbine power cycles and for pulverized coal plants. Oxy-fuel combustion can be performed using conventional atmospheric oxy-fuel combustion power cycles or pressurized oxy-fuel combustion systems that have the potential for even better performance.
The main problem with known oxy-fuel methods is the parasitic power demand for separating oxygen from the air. This is usually completed cryogenically. For a typical 500 MW coal-fired power station, supplying pure oxygen requires at least 15% of the electricity the plant generates.
The technical risks associated with oxy-fuel are potentially less than other clean coal technologies because the technology is less complex and can be retrofitted to old or new coal-fired plants with significant reductions in the capital and operating cost of flue gas cleaning equipment such as de-NOx plant.
CO2 Transport
Carbon dioxide is already transported for commercial purposes by road (tanker truck), by ship and by pipeline. Large networks of CO2 pipelines, mainly associated with CO2 flooding of oil reservoirs for Enhanced Oil Recovery (EOR), have been in use since the early 1980s and are operated commercially with proven safety and reliability records. Most of them lie in the US, where more than 4 000 km of pipelines already exist, with the Permian Basin containing between half and two-thirds of the active CO2 floods in the world.
Movement of CO2 is best accomplished under high pressure. When pressure reaches 81 atm, CO2 enters what is called the supercritical phase (also referred to as a dense vapour phase). Pipeline transportation of CO2 in the supercritical phase is more desirable than transportation in the gaseous phase. As a dense vapour in the supercritical state, CO2 can be transported more economically and efficiently using smaller pipelines and pumps because greater volumes of fluid can be transported as a dense vapour than as a gas. In addition, CO2 would be difficult to transport as a gas because it would enter into two-phase flow at a lower pressure than that required for the efficient pipeline transportation of the CO2.
Carbon storage fields will be needed in many different regions which may be far from the capture sites. Transportation by ship may thus be required for transportation of carbon dioxide over these longer distances. For transportation by ship, the gas is compressed at a pressure of 6-7 bar and cooled down to near −52° C. The liquid CO2 resulting from the liquefaction process is subsequently sent to a CO2 intermediate storage terminal that serves as a port for CO2 carriers and storage tanks. The principal basis for the storage terminal design is that the CO2 stream should be kept in a liquid phase for the entire process. Cryogenic liquids such as liquid CO2 rapidly expand on evaporation; when CO2 expands at 220 K, the fully vaporized CO2 occupies approximately 80 times the volume of liquid CO2. This volume change can occur almost instantaneously, and such an expansion can result in serious damage to the storage system causing, for example, pipeline fractures and tank explosions. The BOG (Boil Off Gas) re-liquefaction system and pipe and tank insulation system could require a large amount of energy depending upon the operating process (see also Ung Lee, Youngsub Lim, Sangho Lee, Jaeheum Jung, CO2 Storage Terminal for Ship Transportation, Ind. Eng. Chem. Res. 2012, 51, 389-397).
CO2 Storage
CO2 storage may involve the injection of CO2 into hydrocarbon fields or the use of carbon dioxide for a process like enhanced oil recovery (EOR). EOR involves the injection of CO2 into a hydrocarbon formation and the extraction of the fluid (mixture of water, CO2 and oil) where CO2 usually is re-injected. The sequestration of CO2 into saline aquifers on land is different from EOR, as it compresses or displaces the existing pore fluid by raising the pressure without extraction of the saline water. The pore fluids frequently contain high concentrations of toxic metal such as arsenic or lead. Displacing such pore fluid from the formation, similar to producing oil during EOR, and then discharging it, would be trading one disposal problem for another. If the permeability of the reservoir is high the management of pressure is not a problem because the pressure is rapidly dispersed. With a large CO2 volume injected within one formation, displacements of saline water and pressure management may prove the greatest challenge for CCS storage.
Since 1996 StatoilHydro has been injecting 1 million metric tons of CO2 per year into a sandstone reservoir—a thick sequence of impermeable shale—that lies 1000 m below the sea surface. The CO2 injection offshore into marine sediment is not direct ocean storage as the CO2 is stored deep beneath the ocean avoiding effects on ocean ecology. The pore fluid in most marine sediment is similar to seawater. As long as there not a high concentration of oil or other hydrocarbons, the release of marine pore fluid to seawater to accommodate CO2 injection will not cause any harm to the marine environment. The ability to manage pressure by drilling additional wells to release pore fluid to the ocean not only provides extra safety to prevent a fracture from allowing CO2 to escape to the surface, but also allows a much higher fraction of the pore space to be used, reducing the footprint of an individual injection field. Marine sediments offer enormous storage potential because reservoirs with adequate permeability in deep water (below 3000 m) are under high pressure and low temperature which would render the CO2 denser than seawater, making the thick, low-permeability cap rock required on land storage to prevent CO2 from escaping less imperative.
Although offshore CO2 storage is much more expensive than for comparable storage on land, it is easier to permit offshore storage than it is to store carbon dioxide in the heavily populated areas of the US or Europe where most CO2 is created but where locating storage sites may be practically impossible because of public opposition and lack of local political support. On the other hand, beyond 3 miles (5 km) offshore, the surface landowner is the national government. The regulations for CCS focus on the contamination of drinking water aquifers, which is not an issue for marine sediments far offshore. Offshore storage also offers a similar advantage in locating pipelines for CO2 transport, which are difficult to site in heavily settled urban areas.
From the foregoing, it is apparent that there are a number of significant obstacles to the implementation of carbon capture and storage technologies. Therefore, more efficient and cost-effective COS technologies that overcome some of these impediments are highly desirable.